Thermal power plants are designed to produce electrical power with steam driven turbines wherein the steam is produced by burning fuel to heat water in a boiler. The fuels used in thermal power plants includes coal, oil, and natural gas and combinations thereof, and in some cases bagasse, wood chips, or even rubber tires. Principal products of combustion include excess oxygen, nitrogen, carbon dioxide, and water vapor. Other by-products of combustion include particulate and ash, sulfur dioxide and sulfur trioxide (for sulfur bearing fuels), oxides of nitrogen, and carbon monoxide. These by-products are harmful to the environment and are considered as pollutants.
The pollution control systems described herein are directed at removing some or all of these pollution components from combustion gases of thermal power plants. The systems are applicable to thermal power units, pulp and paper incinerators, or any exhaust gas from a fuel burning plant. However, some embodiments are ideally suited for use in the operation of thermal electrical generation plants because a significant increase in boiler efficiency may be obtained.
FIG. 1 schematically illustrates various features of a typical thermal power unit including heat recovery equipment from the exit flue gas. Combustion of the fuel in the firebox 1 produces heat to create steam in the boiler 2 from a closed cycle of purified, recirculating water supplied from the feedwater system 3, and boiled in the boiler 2. The steam is used to operate a turbine 4 and generator 5 to produce electrical power. Preheat is usually added to the feed water by feedwater heaters 6 using extraction steam from various stages of the turbine. The water is introduced into the boiler by high pressure feed pumps where it flows through heat exchange tubes 7 contained on the inside surfaces of the boiler's combustion chamber or firebox 1, in which continuous combustion takes place at high temperature.
Fuel is injected into the firebox using a fuel injection system comprising a high pressure fuel pump and fuel line (not shown). Combustion air is injected into the firebox with a combustion air injection system comprising high capacity blowers in the form of forced draft fans 8 and/or induced draft fans 9 and regenerative air preheaters 13 . The resulting heat is transferred to the feedwater through the heat exchange tubes by both convection and radiation, and the water is thereby converted into steam which is used to operate the turbine 4. After combustion, the burnt fuel and air mixture, called flue gas, is expelled from the fire box through the flue 10.
Not all of the heat generated by the combustion process is transferred to the water to produce steam, and often considerable heat remains in the flue gas to be later discharged into the atmosphere from a stack 11 as waste heat. Boiler flue gas temperature in the flue 10 (at point A) will range from about 1500.degree. to 1900.degree. F., and will fluctuate according to boiler operating demands. Downstream from the fire box, just before final exit of the combustion gases from the boiler, it is normal to include a gas-to-water heat exchanger 12, usually called an economizer, to additionally preheat the feedwater supply using the hot flue gas with a resultant decrease in final exit flue gas temperature to between 650.degree. and 800.degree. F. (or higher).
In addition, prevalent design procedure is to include a regenerative air preheater 13 to recover heat from the combustion gases and, by means of rotating metal plates or baskets (not shown), to transfer some of this heat to the incoming combustion air.
Although boiler thermal efficiency is increased by preheating both the water and combustion air, final exhaust gas temperature is lowered as a result, and this reduces the buoyancy of the exiting plume. A less buoyant plume will rise less high from the stack exit into the atmosphere, resulting in less mixing and dilution with the atmosphere, and it will fall more quickly to ground level in the vicinity of the local surroundings, increasing local measurements of pollution levels. The temperature range of exhaust gas entering the stack (at point B) is standardized in the thermal power industry between a low of 250.degree. F. and a high of 400.degree. F. for discharge to either the induced draft fan 9 inlet or, in most cases, directly to the stack 11 (when only a forced draft fan is used).
For sulfur bearing fuels, approximately 1 to 2 percent of the sulfur present in the flue gas normally converts to sulfur trioxide. The acid dew point (point of condensation) of sulfur trioxide as sulfuric acid is about 220.degree. F. As the regenerative air preheater plates pass from the cooler supply air side to the hot combustion flue gas side, average cold end metal temperatures (CEMT) below the acid dew point are presented to the sulfur tri-oxide and this way cause condensation, deposition, and corrosion. Some boilers use steam heat on the entering cold air to raise the CEMT to prevent sulfur trioxide condensation. Whether or not steam heat is used, the condensation of sulfur trioxide can be avoided or minimized by maintaining flue gas temperature and the CEMT well above the acid dew point. Additionally, some fuels such as natural gas have a high water content which carries over as water vapor in the flue gas. In this case, the exit gas temperature is also held in the designated range because of the high water vapor content which would create a dense nonbuoyant and opaque water vapor plume if exhausted at temperatures near the condensation point of water. The latter plume formation is also affected by ambient air mixing temperature.
Thus, corrosion problems and pollution problems have dictated high exhaust temperature and have prevented recoupment of the heat in the exhaust gas. By using the heat content remaining in the flue gas to further preheat combustion air a large gain in thermal efficiency can be realized. Heat recovery from the flue gas to the incoming combustion air (utilizing heat exchangers) represented by a drop in flue gas temperature of 40.degree. F. results in an increase of approximately one percent in boiler efficiency. If there were no problems with corrosion or a water vapor plume, a minimum exit flue gas temperature of 160.degree. to 180.degree. F. would suffice to ensure buoyancy of the plume for acceptable ground level concentrations even if no pollutants were removed, and the boiler efficiency would be increased significantly.